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Who Replaces Venezuela’s Lost Barrels?


The heavy-light imbalance in the global crude market continues to rock tenets that were previously thought immutable. Behind most of the disequilibrium one finds the United States – in the past 5-6 years most of the accretion in global crude production was a result of the US expansion of light sweet shale crude, amidst which the Trump Administration initiated a sanctioning fiesta that saw more than 1mbpd of Iranian medium sour oil scraped off the supplier market and another 1mbpd eliminated from Venezuela’s export portfolio. Ironically, the much-reduced heavy supply hurt primarily USGC refiners, who, with an aggregate heavy crude refining capacity of 2.8mbpd, are best suited to refine Latin American and Middle Eastern heavy barrels. Is there a way out from this for the Gulf Coast?

In the calendar year of 2018, Mexico was the largest supplier of heavy barrels to the United States, exporting some 670 000 barrels per day on an annual average basis (predominantly the 22° API and 3.3 percent Sulphur-containing Maya). Venezuela was second with 0.45mbpd on an annual average basis, spread across a variety of grades that range from the most popular DCO, Zuata, Hamaca to the less frequent Merey and Boscan. Should the United States quit importing Venezuelan crude altogether, for the American national books that would mean a gaping hole of 165 million barrels per year (out of the total 730 million barrels of heavy crude US refiners bought, i.e. almost the quarter) which need to be replaced with something.

There already emerged a rule of thumb which says that whenever OPEC cuts production, it is going to be heavy or medium sour output that is being curtailed. One can see that in the physical movements around the globe in general and the Middle East in particular, one can discern it in the collapse of the Brent-Dubai spread (which traditionally hovered around 3-4 USD per barrel yet dropped as low as some 30-40 cents in January 2019 and only reached 1.5 USD per barrel, i.e. half of the traditional premium, on April 01). As the Vienna Alliance is still keeping a production cut in vigor, it would be logical to assume that if the United States is to procure sufficient volumes of heavy sour crude, OPEC member countries (or OPEC+ participants) would be out of question. Let’s take a closer look.


Even though Mexico is the largest seaborne supplier of heavy crudes to the United States, most of its crude is actually heading to Asia and to a lesser degree Europe, under long-term contracts, which renders the task of increasing Mexican imports quite complex. Moreover, Mexico’s production peaked in 2004 at 3.8mbpd and has fallen since then precipitously, reaching a 40-year low at 1.7mbpd in December 2018. Albeit politically somewhat difficult under current circumstances, there might be a way out to the benefit of both Mexico and the US – crude swaps, whereby some crude destined to be refined in PEMEX’s refineries in Mexico, would be swapped for US light sweet.

This would solve Mexico’s perennial headache, massive fuel oil yields in its refining system, whilst also providing complex USGC refineries with a Venezuelan-lookalike, the Mexican Maya. Yet the chances to see this happen are low – they would be much higher if the United States had a national oil company and not a plethora of firms with varying interests. In the long term, as PEMEX’s long-term contracts with Asian buyers run out and its crude production witnesses some sort of a rebound after 2021, it is fully conceivable that some of those volumes would be reoriented towards the USGC. However, in the short-to-mid-term, US firms must seek for viable solutions elsewhere.


Behind Mexico and Venezuela, Colombia was the third largest seaborne supplier of heavy crude to the United States in 2018, exporting some 62 million barrels (0.17mbpd). Being less contract-bound than Mexico in terms of volume distribution, Colombian grades such as Castilla and Vasconia did manifest a palpable increase in Q1 2019, especially in March when Colombian exports to the US averaged 0.31mbpd. Chevron took in a substantial amount at its Pascagoula refinery, however the geographic spread of Colombian crude was as wide as possible – from New York and Philadelphia to Lake Charles, LA. Yet as with Mexico above, there is a clear limit to which Colombian exports to the US can go – and it is dictated by dropping production in the Latin American country. It simply cannot export more heavy volumes than the 17-18 million barrels (0.5mbpd) it already does.


Angolan exports to the United States did witness a minor renaissance, yet its impact is quite limited. American buyers have been buying two VLCCs per month of heavy sweet Pazflor and Dalia in February and March, most likely the same situation will take place in April. This equates to some 60kbpd per month which pales in comparison to the 0.55mbpd US imported from Venezuela in the pre-sanctions period. Moreover, Angolan crudes are a staple diet of Chinese refiners and this level of demand amidst falling production levels has resulted in grades like Dalia (23.7°API and 0.48 percent Sulphur) appreciating to unseen levels – it traded at a hefty 1.20 USD per barrel premium to Dated Brent as of April 02.

Heavy Crude

(Click to enlarge)

Source: OilPrice data.

This brings us to the following bottom line – US refiners can increase their supplies from Colombia or Angola, yet they cannot overpower the declining production trends there. Moreover, they also have to be ready to outbid Chinese, Indian and other Asia Pacific refining powerhouses that have found themselves in a similar situation. Consequently, their best chance is also the most evident one – turn to Canada, an allied country that already is the United States’ largest crude supplier. Canada is pretty much the only heavy crude-producing nation whose production is on the increase and is being administratively curtailed due to pipeline constraints. Apart from the ever-obvious geographical proximity issue, there is a subtler dimension to the United States opting for more Canadian heavy barrels.

Traditional suppliers of heavy barrels to the American market – PEMEX, PDVSA, Ecopetrol and others – are state-owned national oil companies with little American involvement around. Canada, on the other hand, has no national oil company and its producers are oftentimes very intricately linked to US energy interests (take Imperial Oil, the fifth largest Canadian producer, of which ExxonMobil owns 69.6 percent). Moreover, as Canada matters more and more to US refiners, it would not be hard to imagine US oil and gas majors buying up the most profitable companies in a mirror version of Saudi Aramco buys Asian refiners to whom intends to supply with its own crude.


(Click to enlarge)

Source: EIA.

The above also sheds a different light on President Trump intensifying pressure to have the 830kbpd Keystone XL pipeline construction launched as soon as possible. Last week he issued a new permit for the oil pipeline that would connect Hardisty, Alberta with Steele City, Nebraska, erasing any references to environmental reviews. The previous presidential permit has been in limbo for quite some time after a federal judge in Montana found the State Department’s environmental impact assessment not appropriate to the scale of undertaking. Despite President Trump’s renewed push, things will not be easy for Transcanada, the operator of the pipeline, as it still has an array of court hearings to win, most notably on water quality and route suitability. Yet oddly enough in a world that is increasingly environmentally conscious, fast-tracking Canadian pipeline projects seems the best-suited strategy for the long-term stability of US refining.

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